1. Field of the Invention
The present invention relates to oil and natural gas production. More specifically, the invention is a system and method for fracturing one or more stages of a hydrocarbon-producing well.
2. Description of the Related Art
In hydrocarbon wells, fracturing (or “fracing”) is a technique used by well operators to create and extend fractures from the wellbore into the surrounding formation, thus increasing the surface area for formation fluids to flow into the well. Fracing is typically accomplished by either injecting fluids into the formation at high pressure (hydraulic fracturing) or injecting fluids laced with round granular material (proppant fracturing) into the formation. In either case, the fluids are pumped into the tubing string and into the formation though ports disposed in downhole tools, such as fracing valves.
Fracing multiple-stage production wells requires selective actuation of these downhole tools to control fluid flow from the tubing string to the formation. For example, U.S. Pat. No. 7,926,571, entitled Cemented Open Hole Selective Fracing System, describes one such system for selectively actuating a fracing sleeve using a shifting tool. The tool is run into the tubing string and engages with a profile within the interior of the valve. An inner sleeve may then be moved to an open position to allow fracing or to a closed position to prevent fluid flow to or from the formation.
The most common type of multiple stage fracturing system is the “ball-and-seat”-type system. Ball-and-seat systems are simpler actuating mechanisms than shifting tools and do not require running such tools thousands of feet into the tubing string. Most ball-and-seat systems allow a one-quarter inch difference between sleeves and the inner diameters of the seats of the valves within the string. For example, in a 4.5-inch liner, it would be common to drop balls from 1.25-inches in diameter to 3.5-inches in diameter in one-quarter inch or one-eighth inch increments, with the smallest ball seat positioned in the last valve in the tubing string.
Although ball-and-seat systems are commercially well-established, such systems have inherent drawbacks. While this methodology provides for a quick and relatively cheap solution (in terms of component cost) to open a fracing sleeve, the operator is saddled with inner dimension (ID) restrictions because the ball sizes start out small and progressively work upwell to the largest size.
First, the operator must drop balls of differing sizes to shift the various sleeves. This, however, limits the number of valves that can be used in a given tubing string because each ball would only be able to actuate a single valve, and the size of the liner only provides for a set number of valves with differently-sized ball seats. In other words, because a ball must be larger than the ball seat of the valve to be actuated so that it can engage its corresponding seat, and each ball must also be smaller than the ball seats of all upwell valves so it can pass through them as it travels through the tubing string to its corresponding seat, each ball can only actuate one tool.
Second, producers want to minimize, or altogether eliminate, ID restrictions in order to alleviate and simplify any remedial work that might be required. To achieve this with ball-and-seat systems, operators are forced to drill out the ball seats after fracing, which is very costly and time consuming. Moreover, this methodology presents a number of secondary issues, such as the inherent difficulty of working on a “charged” wellbore after fracing, wearing out mills and having to continuously trip the assembly out of the hole due to the number of sleeves to drill out, having to deal with sand, and the mechanical risk of a tool getting stuck in the hole with the drill out pipe or coil tubing, just to name a few. Such difficulties can increase costs from tens of thousands to hundreds of thousands of dollars.
Third, conventional ball-and-seat systems limit the flow rate of the fracing material within the tubing string. Operators want to maximize pump rates through the fracing system to treat the wellbore in the most efficient manner and get the most extension of fluids and fracing materials into the formation, which thereby increases production. But despite the large number of stages currently desired—modern multiple-stage wells typically run upwards of twenty-four stages—and working in the casing and open hole design sizes, there is only so much cross sectional area to work with.
The smaller balls and corresponding seats in these large systems are required to hold high pressure—usually ten thousand or more psi—which places design constraints on the engagement or contact area with current materials to ensure the ball does not crack, break, or extrude through the ball seat. Finding a ball material and preferred size that allows for the maximum amount of stages and uses the smallest engagement clearance possible requires use of stronger ball materials and affects impact reliability and the ability to drill out the balls following fracing.
Once all these parameters are allowed for, the smallest ball seat size in most cases ends up being as small as one inch in diameter, which can potentially cause premature opening of the sleeve as a result of fracing fluid moving through the sleeve at high flow rates. In order to avoid erosion of the seat and to ensure that the friction and pressure drop of the fracing fluid does not prematurely open or shift the ball seat without a ball, operators are forced to lower their pump rates through the smaller seats at the lower end of the well.
Fourth, these systems are unable to duplicate the “cemented plug and perf”-type completions that have multiple stages per well and in which a well operator perforates multiple clusters of holes for each stage. Operators desire and have proven the effectiveness of this method in that it allows for multiple fluid exit points for each stage and multiple fluid production points, which is important in order to fully and effectively fracture the formation for each stage. As the formation is treated through a single fluid exit point, the rock may break down a significant distance down the wellbore, forcing the fluid to exit the casing and turn the corner in the annulus. This causes near wellbore tortuosity, which in some cases causes premature screen out. It also increases erosion possibilities and problematic friction pressures.
Although some systems are under development to allow for a single ball of each size to open multiple injection points, each of the current systems still relies on using different sizes and have design concerns inherent to their approach. Furthermore, as mentioned supra, current “cemented plug and perf”-type completions utilize pump down composite or similar material plugs, which are set between the zones to stop fluid from fracing into the previous stage. This is costly both in resources and time because it requires the operator to stop fracing during the plug-setting operation, resulting in standby charges for the fracing equipment and increasing completion time from hours to days, or even weeks. This increases the overall cost exponentially without even considering the lost production that could have been made in that time period as well.